Numerical Investigation of Two-Phase Flow through a Fault

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Central Schemes for Porous Media Flows

We are concerned with central differencing schemes for solving scalar hyperbolic conservation laws arising in the simulation of multiphase flows in heterogeneous porous media. We compare the Kurganov-Tadmor, 2000 semi-discrete central scheme with the Nessyahu-Tadmor, 1990 central scheme. The KT scheme uses more precise information about the local speeds of propagation together with integration over nonuniform control volumes, which contain the Riemann fans. These methods can accurately resolve sharp fronts in the fluid saturations without introducing spurious oscillations or excessive numerical diffusion. We first discuss the coupling of these methods with velocity fields approximated by mixed finite elements. Then, numerical simulations are presented for two-phase, two-dimensional flow problems in multi-scale heterogeneous petroleum reservoirs. We find the KT scheme to be considerably less diffusive, particularly in the presence of high permeability flow channels, which lead to strong restrictions on the time step selection; however, the KT scheme may produce incorrect boundary behavior

Understanding the Impact of Open-Framework Conglomerates on Water-Oil Displacements: Victor Interval of the Ivishak Reservoir, Prudhoe Bay Field, Alaska

The Victor Unit of the Ivishak Formation in the Prudhoe Bay Oilfield is characterized by high net-to-gross fluvial sandstones and conglomerates. The highest permeability is found within sets of cross-strata of open-framework conglomerate (OFC). They are preserved within unit bar deposits and assemblages of unit bar deposits within compound (braid) bar deposits. They are thief zones limiting enhanced oil recovery. We incorporate recent research that has quantified important attributes of their sedimentary architecture within preserved deposits. We use high-resolution models to demonstrate the fundamental aspects of their control on oil production rate, water breakthrough time, and spatial and temporal distribution of residual oil saturation. We found that when the pressure gradient is oriented perpendicular to the paleoflow direction, the total oil production and the water breakthrough time are larger, and remaining oil saturation is smaller, than when it is oriented parallel to paleoflow. The pressure difference between production and injection wells does not affect sweep efficiency, although the spatial distribution of oil remaining in the reservoir critically depends on this value. Oil sweep efficiency decreases slightly with increase in the proportion of OFC cross-strata. Whether or not clusters of connected OFC span the domain does not visibly affect sweep efficiency.Comment: 27 pages including 14 figure

Comparison of CO2-EOR performance between offshore and onshore classes of reservoirs

CO2 has been extensively used in onshore fields, primarily for EOR. However, it has been used less offshore due to limited transportation infrastructure and the lack of secure CO2 supply. Recently, CO2 flooding has been reconsidered in offshore fields for both EOR and storage. The performance of CO2 flooding in the offshore classes of reservoirs, which are characterised by fundamentally dissimilar properties and development characteristics than onshore reservoirs, might be different from the past experience of CO2 flooding observed onshore. Offshore developments are characterised by higher rates of depletion, fewer wells, larger well spacing and higher well rates compared to onshore reservoirs which are characterised by pattern development and shorter well spacings; moreover, the motivation behind CO2 flooding might be different offshore. The aim of this study is to review these differences between CO2 flooding in offshore and onshore classes of reservoirs, exclusively within the context of reservoir engineering. In the first part of this study, different aspects of CO2 flooding are compared between two major provinces i.e. the onshore Permian Basin province located in the United States and the offshore North Sea province. It will be shown that CO2-EOR has many similar characteristics in these two provinces despite the fact that ambient reservoir conditions are fundamentally different between them. Next, flow patterns are compared between these two classes of reservoirs. Flow patterns in each of reservoirs are investigated by deriving the key dimensionless numbers which may characterise CO2 flooding in each of them. It will be shown that CO2 flooding is slightly more gravity dominated in the North Sea class of reservoirs. Additionally, in the absence of gravity effects, flow patterns upon CO2 flooding are expected to be more stable in the North Sea class of reservoirs due to better mobility ratios that characterise the displacement in this province. The fact that the motivation for CO2 flooding is potentially different between these two classes of reservoir may also promote alternate CO2 flooding process designs offshore, which should satisfy both the EOR and storage requirements of CO2 flooding in the offshore class of reservoirs. The second part of this thesis investigates the grid size requirements for modelling miscible processes such as CO2-EOR. A new approach based on measuring heterogeneity induced dispersivities in longitudinal and transverse orientations is introduced and developed. Matching these dispersivities with equivalent numerical dispersion may determine the correct size of grid blocks in a miscible displacement simulation

Immiscible displacement of trapped oil through experimental and data mining techniques.

Extensive experimental and data mining techniques have been applied to investigate the potential and competitiveness of gases used in immiscible gas-enhanced oil recovery (EOR) processes. Methane (CH4), Nitrogen (N2), Air (21%O2/N2) and Carbon Dioxide (CO2) are some of the gases injected in reservoirs to displace trapped oil from reservoir pores. The EOR screening process has been well-documented in the literature. However, for immiscible gas EOR technology, very few resources are available for evaluating the selection and performance criteria for commonly-injected EOR gases; immiscible EOR gases are usually lumped up in published screening models, and the gases are reportedly selected based on availability and accessibility, rather than on technical criteria such as displacement efficiency. Furthermore, available experimental studies have investigated EOR gases only separately. This research has been able to fill these gaps and more, through rigorous data mining and gas experiments processes. The methodology utilised empirical approaches set in three phases. Phase I applied data mining techniques to 10,850 data from 484 EOR field projects, to identify twenty-four EOR geological and engineering quantities, and objective functions. Phase II utilised Phase I outcomes to design and execute a set of rigorous gas experiments, involving 1,920 experimental runs (comprising five reservoir analogous core samples, eight gases, eight isobars and six isotherms), to generate and analyse 15,360 experimental data points. Several established and modified constitutive equations were used to model gas responses to EOR geological and engineering quantities. In Phase III, Phase I and Phase II results were coupled for the purpose of knowledge validation and application. This research's outcomes have contributed to reservoir engineering practice and knowledge in providing useful information on EOR gases' competitiveness. Results from Phase I indicate that immiscible gas EOR can be unbundled through data mining and clustering techniques. A novel screening model has been developed for immiscible gas EOR that incorporates sensitivity and criticality markers for each petrophysical quantity investigated. It has been demonstrated in Phase II that, in a heterogeneous system, CH4 is the most competitive gas for ten geological and engineering quantities and objective functions, such as Volumetric Rate, Interstitial Velocity, and Well Density. Similarly, CO2 is most competitive for ten other quantities investigated, such as Mobility and Interstitial Momentum. N2 is the most competitive for the cost of injected gas per area coverage. Air is second-best for several objective functions. Suffice to state that at some structural settings and operational conditions (such as porosity, pore size, surface area and temperature), the competitiveness ranking of the gases switches position. Such was observed between N2 and CO2 in low porosity (4% and 3%) core samples. EOR gas mixtures and non EOR gases - such as 20% CH4/N2, He, and Ar - were added to the experiments to investigate the relationship between gas flow and gas properties. It was observed that the structural variability (heterogeneity) of the system distorts the correlation between gas properties, such as molecular weight, and the performance criteria of the respective gases. The results from Phase I and II couple significantly in Phase III. Based on well number and placement, it has been demonstrated that the well placement of CH4, CO2, and Air favours a negative pore size gradient, while N2 favours a positive gradient. The economic analysis demonstrates that CO2 incurs the least cumulative injectant cost and the highest capital expenditure cost (CAPAX). The three Phases validate the field and laboratory well density profile. CH4 requires the least well density (0.2 well/acre, 1.0 well/cm2) compared to CO2 (0.7 well/acre, 2.0 well/cm2). In some analyses, it was discovered that gas mixture, such as 20%CH4/N2, performs better than when the individual component gas acted alone. Single-phase and two-phase relationships have been analytically and experimentally coupled. The experimental findings at low pressure could also lend utility to the gas separation, fluidised bed, and catalytic reaction processes and industry

Evaluation of various CO2 injection strategies including carbonated water injection for coupled enhanced oil recovery and storage

In view of current interest in geological CO2 sequestration and EOR, this study investigated water-based and gas-based CO2 injection strategies for coupled EOR and storage purposes. For water-based CO2 injection strategy, carbonated water injection (CWI) was investigated as an alternative injection mode that could improve sweep efficiency and provide safe storage of CO2. Despite its potential, CWI has not been very much studied. This thesis presents the details on the performance of CWI of moderately viscous oil (>100 cP), which has not been reported before. The effects of oil viscosity, rock wettability and brine salinity on oil recovery from CWI were also studied and significant findings were observed. To the author’s knowledge, no attempt has been made to experimentally quantify the CO2 storage by CWI process and to model the nonequilibrium effects in the CWI at the core scale using the commercial reservoir simulators. These are amongst the main innovative aspects of this thesis. The experimental results reveal that CWI under both secondary and tertiary recovery modes increase oil recovery and CO2 storage with higher potential when using light oil, low salinity carbonated brine and mixed-wet core. In this study, the compositional simulator overpredicts the oil recovery. The instantaneous equilibrium and complete mixing assumptions appear to be inappropriate, where local equilibrium was not in fact achieved during the CW process at this scale. The author evaluated the use of the transport coefficient (the a-factor) to account for the dispersive mixing effects, and found that the approach gives a more accurate prediction of the CWI process. For the gas-based CO2 injection strategies, a practical yet comprehensive approach using reservoir simulation, Design of Experiment (DOE) and the Response Surface Model (RSM) to screen for and co-optimize the most technically and economically promising injection strategy for coupled EOR and CO2 storage is presented. For the reservoir model used in this study, miscible WAG was found to be most economically promising, while miscible continuous CO2 injection was ranked as the most technically viable. The duration of the preceding waterflood, relative permeability (wettability) and injected gas composition are the three most significant factors to the profitability of oil recovery and CO2 storage through tertiary WAG injection

Design of Optimal Storage and Recovery Strategies of Carbon Dioxide using the Wytch Farm Reservoir Model

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Matrix Fractures Exchanges in Naturally Fractured Reservoirs under EOR Mechanisms

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Physical model experiments of the gas-assisted gravity drainage process

The displacement of oil by gas injection in oil reservoirs is an attractive method of improved oil recovery. Commercial gravity-stable gas injection projects have demonstrated excellent recoveries; however, their application has been limited to dipping reservoirs and pinnacle reefs. Horizontal gas floods and the water alternating gas (WAG) processes, practiced in horizontal type reservoirs, have yielded less than satisfactory recoveries of 5-10%. The Gas Assisted Gravity Drainage (GAGD) Process being developed at LSU extends the concept of gravity-stable gas floods to horizontal type reservoirs to improve volumetric sweep and oil recovery. This experimental study consists of a series of visual experiments to study the effects of operating parameters such as capillary number, the Bond number, gravity number and mobile water saturation on the GAGD process. The experiments were performed in a visual physical model packed with uniform glass beads of various sizes and by injecting gas at various pressures, rates and initial water saturations. The results have been correlated against dimensionless numbers characterizing the role of gravity and capillary forces. This has also enabled the comparison of the physical model results with those from core floods and field projects. The run time of the physical model experiments have been scaled to the required time in the field to obtain similar recoveries. Good correlations are obtained between the Bond and capillary numbers with cumulative oil recovery. Results indicate that these correlations are not only valid for immiscible GAGD floods but may be applicable for miscible GAGD floods. This enables us to predict oil recoveries from similar processes on commercial scale if sufficient rock and fluid data is available. Significantly better oil recovery is obtained during the early life of the project at constant pressure gas injection. Higher recoveries are obtained during gravity-dominated flow as opposed to capillary or viscous dominated. Experimental results show that the composition of the injected gas has little effect on oil recovery during immiscible gas injection. Recovery versus gravity number data from the physical model, core floods and commercial field projects, all fall close to a straight line on a semilog plot. This indicate that the physical model is capable of capturing the realistic mechanisms operating in the field projects and that these experimental runs may be reasonably extrapolated to field scale